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Robin Watts Oil & Gas Technology Manager, Oil & Gas Services, Linde LLC

Oil and Gas Services. Energized Solutions …Fracturing fluid selection

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Content

1 Linde Introduction

2 Energized Fluids

3 Fluid Selection – Performance & Economics

4 Recommendations

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Leveraging Synergies

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1879

~$20 billion

~62,000

>100

Linde Engineering Technology-focused Air Separation

Global #1

CO2/Syn Gas

Global #2

Olefins

Global #2

Natural Gas

Global #3

HyCO Tonnage Plants

>70 plants

ASU Tonnage Plants

>300 plants

ECOVAR Std Plants

>1,000 plants

Linde Gas - Tonnage World-class operations

Founded

Sales

Employees

Countries

CO2 Plants

>100 plants

The Linde Group Overview

The Linde Group in North America

4

—Industry leading National Operations Center, New Jersey

—Linde Gas HQ: Murray Hill, NJ

—US Linde Engineering facilities:

—Blue Bell, PA (Selas Fluid Processing)

—Holly Springs, GA (Hydrochem) —Tulsa, OK (Linde Process Plants)

>$5 billion

>15,000

>400 (gas & merchant)

>100,000

Sales

Employees

Locations

Customers

40,000 / month

80 million

1,200 drivers

800 tractors

1,200 trailers

650 railcars

Deliveries

Miles

Fleet Size

Drivers

Tractors

Trailers

Railcars

Note: Sales & employees include Lincare

Industry Leading Gas (CO2, N2) Network for: E&P: EOR Well Pad Services Pipelines & Plants LNG as a fuel

N2 and C02 EOR Hydraulic fracturing with CO2 and N2

Coiled tubing services N2 supply

Purging, pressure testing, pigging

Drying, hot stripping Accelerated reactor

cooldown

Drilling rigs Hydraulic fracturing

spreads

5

• 11 years without lost time injury: *All well sites are inspected and have a

documented “Risk Assessment” performed

*Dedicated off road distribution personnel and equipment

• 20 operators with over 200 years of overall experience

Energy Solutions Serving a broad range of segments

• 9, 16,700 gal queens capable of pumping 550 GPM at 110 PSIG

• 8100 tons of portable CO2 storage

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Linde Oil & Gas Technology and solutions

Innovation

R&D activities focus in particular on the impact of exploration and production processes: improve productivity (EUR), economic efficiency, reduce environmental footprint

— Mobile Gas Clean-up Unit of CO2 from early flowback Natural Gas

— LNG Drilling and Frac Spreads

— EOR Huff-n-Puff

www.lindeoilandgas.com

Energized Fluids 40 years of success

Definition of an energized fluid

— Fracturing fluid that includes at least one compressible, sometimes soluble, gas phase.

CO2 & N2 solutions developed and successfully used for hydraulic fracturing for >40 years

— The original “waterless frac” — 70 Quality CO2 Foam referred to as the Gold Standard of fracturing fluids

Benefits in unconventional reservoirs — Alternative when water-based fracturing fluid interactions with the rock formation

is detrimental to hydrocarbon production. — References on benefits King (1985), Mazza (2001), Burke et al. (2011), Gupta

(2011)

Water sensitivity of the formation — Based upon mineral composition of the rock formation. Energized fluids recommended to prevent

excessive fines migration and clay swelling.

Proppant conductivity & placement — In many shales & clay-rich sands, water softening the rock considerably lowers proppant pack conductivity

due to proppant embedment. — High quality foams provide high effective viscosity for ideal proppant placement over low viscosity slick

water. CO2 and N2 at lower qualities can be gelled to provide viscosity comparable to gelled water.

Fluid Selection Factors to consider – water issues

Low Permeability Reservoir Rock

Shanley et al. AAPG Bulletin 2004

Fluid Selection Factors to consider – water issues cont.

Water blocking — In tight, under-saturated formations, fracturing water

imbibed into the rock matrix pore space remains trapped due to capillary retention.

— Water saturation increases from ~10-50%. Productivity impacted as relative permeability lowers, by sometimes orders of magnitude.

— (Perekh et al. 2004, Mahadevan et al. 2005)

Water availability & cost — Drought-prone, limited water supply, & restrictive local

legislation regions overlap O&G exploration & production areas driving operators towards alternatives.

— Fully accounting for water life-cycle cost – acquisition, management and disposal – of water as a fracturing fluid means it can be more costly to use then energized fluids with CO2 or N2.

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Fluid Selection Increasing Demand & Supply Constraints of Water

Water Resource Planning Division, Texas Water Development Board

New study found that more than 1,100 counties -- one-third of all counties in the lower 48 – will face higher risks of water shortages by mid-century. More than 400 of these counties will f extremely high risks of water shortages.

National Resource Defense Council

Projected Water Demands and Existing Supplies

Enhancement of the 3 E’s – Economics, EUR, Environment

— In well-designed hydraulic fracturing processes, energized fluid solutions utilizing CO2 or N2 can reduce costs & improve well performance to achieve a lower unit cost of production.

Selection methodology — Avoid trial-and-error approach in the field. Utilize the best

energized fracturing fluid / well productivity model and fluid life-cycle estimations to narrow approach followed by field performance data.

Fluid Selection Objective and approach - WHICH HYDRAULIC FRACTURING FLUID SHOULD BE USED FOR A GIVEN RESERVOIR?

Economic Benefits: Tools for Energized Fluids Simple Calculator Tool

for comparing estimated total cost of options - Acquisition, management, disposal calculations

Productivity Simulator Tool

for comparing estimated productivity factor of hydraulic fracturing fluid options

Hydraulic fracturing simulator designed to fully account for the phase behavior and compositional changes of an energized fluid

Example 3: Marcellus CO2, 70 QualityWater disposal leads to water being the most expensive choice

Water acquisition rises from $3 to $13/bbl; disposal rises from $14 to $25/bbl

Fracturing Fluid Cost Comparison - Marcellus, 22 stage wellIncremental

Acquisition, Management (post-frac), Best Case Water CO2& Disposal Cost TOTAL: 1,564,235$ 1,657,714$

DELTA cost of water to CO2 (93,479)$

COST/bbl Equivalent Water CO2acquisition, management disposal 17.65$ 18.70$

IncrementalAcquisition, Management (post-frac), Worse Case Water CO2

& Disposal Cost TOTAL: 3,182,044$ 1,657,714$

DELTA cost of water to CO2 1,524,330$


SPE-166113-MS • A Day in the Life of a Barrel of Water • Robin Watts

SPE 163867 • Fluid Selection for Energized Fracture Treatments • Lionel Ribeiro

Fluid Performance & Economics Cost Comparison of $/bbl Fracturing Fluids Total Cost = Acquisition + Management + Disposal (simplified)

$10 $15 $20 $25 $30 $35 $40 $45WaterMarcellus/Utica

At 100% of water only volumeAt 75% of water only volume

70 quality, $250/ton



With 40% flowback

Productivity index and improved hydrocarbon productivity.

“GOLD STANDARD”

Fluid Performance & Economics Investigating fluid performance – Example

Fluid Performance & Economics Energized Fluids performance benefits

Improve Conductivity, Reduce Water Damage, Reduce Water Retention, Minimize Water Contact

— Cleaner Proppant Pack minimize fines and residues in proppant pack reduce fines migration out of clays over time by minimizing water contact during flowback and

production — Reduce Clay Swelling minimize water introduced into formation over time by minimizing water contact during flowback and production — Reduce Proppant Embedment in softer rock during high pressure pumping of slick water treatments over time by minimizing water contact during flowback and production — Mitigate Water Migration (via leak-off and natural fractures) into formation minimize increase in water saturation which lowers relative permeability and production

— Minimize Water Blockage CO2 enhanced hydrocarbon miscibility improves production CO2 superior solubility minimizes water invasion into formation, enhancing production

(especially over time – less water initially and quicker return)

Fluid Performance & Economics Investigating fluid economics & production – Example

When water usage and disposal is difficulty and costly, equivalent cost quickly rise and water becomes the more expensive option!

-- Best case scenario

-- Recycled water acquisition increases from $5 to $25 per barrel, disposal from $5 to $8/ bbl

Productivity implications…

Example 2: UintaA Day in the Life of a Barrel of Water –Costs

SPE 166113-MS Watts


Average daily production rates for 11 wells during ~7 months of production in 3 county region of Utah.With no CO2 or lower quality CO2, water production was 4.5 to 1.8 times greater than using higher quality CO2. Gas

production was, on average, 5% to 75% higher when using low to higher quality CO2, compared to water.

Example 2: UintaA Day in the Life of a Barrel of Water –Productivity


Example 3: Marcellus CO2, 70 QualityWater disposal leads to water being the most expensive choice



Acquisition, Management (post-frac), Best Case Water CO2& Disposal Cost TOTAL: 1,564,235$ 1,657,714$

DELTA cost of water to CO2 (93,479)$


IncrementalAcquisition, Management (post-frac), Worse Case Water CO2


DELTA cost of water to CO2 1,524,330$



Example 3: Marcellus N2, 60 QualityWater disposal leads to water being the most expensive choice



Acquisition, Management (post-frac), Best Case Water N2& Disposal Cost TOTAL: 1,468,147$ 2,004,075$

DELTA cost of water to N2 (535,928)$

COST/bbl Equivalent Water N2acquisition, management disposal 18.01$ 24.58$

IncrementalAcquisition, Management (post-frac), Worse Case Water N2


DELTA cost of water to N2 951,984$

COST/bbl Equivalent Water N2acquisition, management disposal 36.26$ 24.58$

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Energized Fluids – Recommendations to improve the 3 E’s Economics, EUR, Environment

In well-designed hydraulic fracturing processes, energized solutions utilizing CO2 or N2 can reduce costs (such as clean up and disposal) and improve well performance to achieve a lower unit cost of production. Evaluating the total life cycle of water used in well completions and production is paramount to understanding its true costs. If full life-cycle cost of water is $5-10/bbl, suggest looking at energized fluids to:

– reduce total costs

– improve well productivity (lowering unit cost of production)

– reduce environmental footprint via water and emissions reduction


Thanks for your attention.


BACK UP

CO2 and N2 Fracturing Fluid Properties CO2 Phase Diagram – phase behavior changes during fracturing

CO2 and N2 Fracturing Fluid Properties Unit Conversion – Linde Gas Calculator APP

Properties of Carbon Dioxide or CO2: Molecular weight 44 Melting point -56.6°C Boiling point -78.5(s)°C Critical temperature 30°C Relative density, gas 1.52 (air=1) Relative density, liquid 1.03 (water=1) Vapor Pressure 20°C 57.3 bar Solubility in Water 0.9 vol/vol Properties of Nitrogen or N2: Molecular weight 28 Melting point -210°C, -345.75 F Fahrenheit Boiling point -195.8(s)°C, -320.44 F Fahrenheit Critical temperature 147°C Relative density, gas 0.97 (air=1) Relative density, liquid 0.81 (water=1) Vapor Pressure 20°C 57.3 bar Solubility in Water 0.02348 vol/vol

CO2 and N2 Fracturing Fluid Properties Solubility in Water

CO2 N2

CO2 and N2 Fracturing Fluid Properties Miscibility in Hydrocarbons

CO2 lowers the cricondenbar of the mixture and increases miscibility. If sufficient quantities of the CO2 components are added to a reservoir fluid and the reservoir pressure is kept above the phase envelope, a single dense fluid phase exists. Although the actual mechanism is more complex, it is this solubility that is the primary driving force behind miscible flood enhanced oil recovery projects.

Nitrogen, on the other hand, raises the cricondenbar and decreases miscibility. It is sometimes used for pressure maintenance. There are also a few nitrogen miscible floods. Water, virtually immiscible in the hydrocarbon liquid phase, does not have a significant effect on the shape of the hydrocarbon phase envelope except at high temperatures and low pressures.

CO2 and N2 Fracturing Fluid Properties Interfacial Tension

CO2 and N2 Fracturing Fluid Properties Hydraulic Fracturing Properties

CO2 N2

Fluid State when pumped Liquid Gas

Thermal Conductivity, BTU/min*○F*ft

0.21 0.25

Heat Capacity, BTU/lb 0.21 0.25

Critical Pressure, psi 1072.0 493

Critical Temperature, ○F 87.8 -232.6

Reference Density, lbs/ft^3 52.0 18.0

Typical Pumping Quality Range 30-80 30-70

CO2 and N2 Fracturing Fluid Properties “Foam” Quality – Rheology and Leakoff

N2 or CO2Foam Quality

Liquid Leak-off Coeffecient

(ft/sqrt(min))*

% Improvement over pure

Water0 0.0034 na

25%30%40% 0.0023 32%50%55% 0.0021 38%60% 0.0023 32%62% 0.0021 38%65%68% 0.0017 50%70% 0.001 71%75% 0.0008 76%

*low permeability <1.5mD, pressure drop </= 1000psi

CO2 and N2 Fracturing Fluid Properties Relative Permeability

Fluid Performance & Economics Investigating fluid performance

Fluid rheology, phase behavior / density, composition — Density affects fracture geometry, horsepower requirements, proppant transport

— Compressible energized fluids expand as rock formation heats up fluid

— CO2 more soluble than N2 in water. During flowback, CO2 comes out of solution in water phase, increasing gas saturation and facilitating the flow of hydrocarbon fluids to the wellbore.

— Leak-off coefficient of each phase – Stable foams of CO2 and N2, reduce leak-off significantly as increase foam quality

Critical reservoir parameters — Relative permeability curves: Fluid impact on relative pemeability to gas (oil) in the reservoir

— Initial gas (oil) saturation: Water lost to formation will remained trapped lowering relative permeability and hence, production

— Water sensitivity of formation: Clays do not significantly interact with CO2 and N2 whereas unconventional rock tends to lose mechanical integrity when place in contact with water

— Reservoir pressure: drawdown pressure must exceed capillary forces, energized fluids enhances

— Proppant embedment: shales softened by water contact increase embedment & fines migration, decreasing conductivity and lowering productivity

Fluid Performance & Economics Investigating fluid performance – Relative Permeability Curves

Dimensionless permeability in the invaded zone, Target Foam Quality where kd/k > 0.1

SPE 163867 Ribeiro

Fluid Performance & Economics Fracturing performance simulator – University of Texas at Austin

SPE 15982 Ribeiro

Fluid Performance & Economics Investigating fluid performance – Example

Simulation example – low-permeability sand formation

SPE 163867 Ribeiro

“GOLD STANDARD” Room to improve since relative permeability >0.1

Relative Permeability Unconventional target of >0.1

Wellbore Temperature Profile Example 60 Quality CO2 in EagleFord

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References

PAPERS: Fluid Selection for Energized Fracture Treatments, SPE #163867, L. Ribeiro, M. Sharma, 2013. Society of Petroleum Engineers Novel CO2-emulsified viscoelastic surfactant fracturing fluid system, SPE #96202, R. Hall, SPE, Strat Land Exploration Co., and Y. Chen, SPE, T.L. Pope, SPE, J.C. Lee, SPE, and S. Lugibihl, SPE, Schlumberger , 2005. Society of Petroleum Engineers Key Attributes of Canadian and U.S. Productive Shales: Scale and Variability, Basim Faraj and Meghan Brown, Search and Discovery Article #110129 (2010) Simulation and Design of Energized Hydraulic Fractures, Kyle Eugene Friehauf, Dissertation, Doctor of Philosophy, University of Texas at Austin, August 2009 Fluid Selection for Energized Hydraulic Fractures, SPE #124361, Kyle E. Friehauf and Mukul M. Sharma, University of Texas at Austin, 2009 Society of Petroleum Engineers Application of a New Compositional Model for Hydraulic Fracturing With Energized Fluids: A South Texas Case Study, SPE #119265, Kyle E. Friehauf and Mukul M. Sharma, University of Texas at Austin, and Richard Sullivan, Anadarko Petroleum Corp., 2009 Society of Petroleum Engineers Refracs – Why Do They Work, And Why Do They Fail? A review of 143 published field examples, SPE #134330, Mike Vincent, March 1, 2011 Untested Waters: The Rise of Hydraulic Fracturing in Oil and Gas Production and the Need to Revisit Regulation, Hannah Wiseman, Published in 20 FORDHAM ENVTL. L. REV. 115 (2009) Thirty Years of Gas Shale Fracturing: What Have We Learned?, SPE #133456, George E. King, Apache Corporation, 13 May 2011, SPE GCS Reservoir Study Group Forum Development and Field Application of a Low-pH, Efficient Fracturing Fluid for Tight Gas Fields in the Greater Green River Basin, Wyoming, SPE #116191, Gupta, Jackson, Hlavinka, Evans, Le, Batrashkin, Schaefer, November 2009 SPE Production & Operations Improved Hydraulic Fracture Performance with Energized Fluids: A Montney Example, Lyle H. Burke, P.Eng., RPS Energy, Calgary, Alberta, Canada, Grant W. Nevison, P.Eng., Nevison Consulting Inc., Calgary, Alberta, Canada, Recovery 2011 CSPG CSEG CWLS Convention Associative Polymer System Extends the Temperature Range of Surfactant Gel Frac Fluids, SPE #141260, Gupta and Carman, 2011 Society of Petroleum Engineers Liquid-Free Stimulations - CO2\Sand Dry-Frac, R. L. Mazza, ([email protected]; 330-499-3823), Petroleum Consulting Services, P. O. Box 35833, Canton, OH 44735 Analysis of Production Response to CO.2/Sand Fracturing: A Case Study, SPE #29191, A.B. Yost 11,U.S. DOE R.L. Maz.za, Petroleum Consulting Services; and R.E. Remington II, Universal Well Services, “DRILLING AND COMPLETION PRACTICES IN THE BOOCH SANDSTONE. OR HOW TO MAKE MONEY DRILLING THE BOOCH”, Max Tilford, Tilford Pinson Exploration, LLCEdmond, Oklahoma, February 25, 2009

PRESENTATIONS: “Key Considerations for Hydraulic Fracturing of Gas Shales”, Randy LaFollette, BJ Services Company, September 9, 2010 “Formation Damage”, George E. King Engineering, 3/14/2009 “Fracturing Basics”, George E. King Engineering, 3/14/2009 “A Guide to Fracturing”, George E. King Engineering “Modeling Frac‐Fluid Rheology & Leakoff”, R.D. Barree, 2009 “After the Shale-Gas Multi-Stage Frac – Recovering Valuable Operating Information on the Flowback”, George E. King, 16 September 2009, SPE GCS Westside Study Group “Advanced Fracturing Technology for Tight Gas: Where is the Proppant Going?”, PhaniB. Gadde, YajunLiu, Jay Norman, Roger Bonnecaze, Mukul M. Sharma, David Copeland, COGA Conference, Denver, 2003 “Modeling Energized Fracs”, Kyle Friehauf, Mukul M. Sharma, University of Texas at Austin “Energized Fracturing Treatments”, LIONEL RIBEIRO, MUKUL M. SHARMA, The University of Texas at Austin US EPA, Sudy of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report, December 2012. National Resources Defense Council, Water Sustainability Study, 2012. EPA Hydraulic Fracturing Study Plan, EPA/600/R-11/122, November 2011. Halliburton, Shale Water Management Initiative 2012 presentation, November 29, 2012. API, Guidance/Best Practices on Hydraulic Fracturing, HF2 – Water Management Associated with Hydraulic Fracturing, 1st Edition, June 2010 Devon, API Workshop on Commitment to Excellence in Hydraulic Fracturing October 4th, 2011, Pittsburgh, PA Managing the Risk of Shale Gas: Identifying a Pathway toward Responsible Development, A Review of Shale Gas Regulations by State, Center for Energy Economics and Policy, www.rff.org/shalegasrisks, Updated July 9, 201 Linn Energy, Shale Gas Water Management Initiative 2012 presentation, November 29, 2012. Shell Global Solutions, Shale Gas Water Management Initiative 2012 presentation, November 29, 2012. University of Texas, eFrac well simulation program for energized fluids Production data from State of Utah Oil and Gas, Division of Oil, Gas, and Mining, http://oilgas.ogm.utah.gov/index.htm; Completions data from FracFocus.org. BOOKS: Hydraulic proppant fracturing and gravel packing, Detlef Mader, 1989 Elsevier Modern Fracturing - Enhancing Natural Gas Production, Michael J. Economides and Tony Martin (editors), January 1, 2008


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